In the production of oil, gas and other minerals, certain properties of the subterranean reservoir must be determined. Two of the key, most commonly measured properties are the porosity and permeability of the reservoir. The porosity of a material is the ratio of the aggregate volume of its void or pore spaces (i.e., pore volume) to its gross bulk volume and, in the case of an oil or gas reservoir, is a measure of the capacity within the reservoir rock which is available for storing oil or gas. The permeability of a material is a measure of the ability of the material to transmit fluids through its pore spaces and is inversely proportional to the flow resistance offered by the material. Also, it is often desirable or necessary to measure other physical conditions of media material. Such conditions include, for example, the fluid saturation of the material. Fluid saturation affects the permeability of a reservoir. Thus, in the solution of many problems relating to the performance of a subterranean reservoir, it is necessary to measure the fluid saturation of a core sample taken from the reservoir. By saturation is meant the percentage of the pore volume filled with each of fluid phases contained within the sample. This measurement is required, among other reasons, for determination of the relative permeability of the media sample, i.e., the ratio of the permeability to a given fluid in the presence of another fluid or fluids and the permeability to the given fluid in the absence of any other fluid.
Porosity and permeability are determined by taking core samples from the reservoir site and carrying out well-defined measurement techniques on the samples. There are several techniques available for making such measurements, many of which are described in Petroleum Production Engineering Development by L. C. Uren, Fourth Edition, McGraw-Hill Book Company, Inc., 1956, pps 660-669. Another standard reference for core sample analysis is the API Recommended Practice of Core-Analysis Procedure, API RP40, American Petroleum Institute, 1960, 55 pps. While these procedures are suitable for measuring the porosity and permeability of a sample, they do not address techniques capable of adequately assessing the contribution of reservoir fractures to overall production.
Fluid saturations in reservoir cores and in formations are normally determined by electrical resistivity techniques. Resistivity techniques are described, generally, in Fundamentals of Formation Evaluation by D. P. Helander, OGCI Publications, Tulsa, OK, 1983, as well as in U.S. Pat. Nos. 2,745,057 and 2,802,172. These techniques develop a calibration curve for the matrix rock that is characteristic of the void spaces of the matrix. This is done by taking conductance measurements of the matrix at varying water saturation levels. This technique works well for cores with uniform pore spaces but does not work very well for vuggy cores or for cores with fractures. With regard to cores with fractures, the fractures act as a direct short for the measurement and yield results that are not representative of the total core. Because of this, analysis of fluid saturations in fractures cannot be determined by resistance techniques.
Fractures play an important role in reservoir behavior, having the ability to either enhance or restrict fluid flow in reservoirs. Furthermore, fractures can alter the apparent permeability and/or pososity of the rock. Because of these important influences, the impact of fractures on reservoir behavior must be fully understood in order to accurately model and effectively engineer a given reservoir.
All reservoirs are probably fractured to some extent. Reservoir fracture systems are often complicated, interconnected arrays of fluid flow paths. In fractured reservoirs the preferred flow path is established through these interconneting fractures since they exhibit higher permeability (lower resistance to flow) than does the porous matrix. However, like porous media, relative permeability curves are needed to accurately describe multi-phase flow in fractures. Before the interconnected array can be studied, the simplest case of a single fracture must be studied.
It is therefore an object of this invention to provide a method and system for determining the fluid saturation of a natural or simulated fracture.
It is another object of this invention to provide a method and system for determining the fluid saturation of a natural or simulated fracture present within a core sample.
It is a further object of this invention to provide a method and system for determining the water saturation of a natural or simulated fracture present within a core sample which contains at least one other fluid phase.
It is yet another object of this invention to provide a method and system for determining the fluid saturation of a natural or simulated fracture present within a core sample during measurement of relative permeability.
Other objects of the invention will become apparent from the following detailed description thereof.